1. Field of the Invention
The present invention relates generally to increasing production of natural gas from natural gas reservoirs, and more particularly, but not by way of limitation, to a method for increasing gas well production from high water condensate content gas areas located within natural gas reservoirs.
2. Brief Description of the Related Art
It is only recently within the oil and gas industry that the concept of “stripper” gas well production has been recognized and addressed. A stripper gas well is typically a mature gas well that produces a limited amount of natural gas. The enhancement and retention of natural gas production has largely been secondary or even non-existent compared to newer technologies directed toward the development of advanced oil recovery techniques. However, natural gas has reached the forefront of valued energy commodities due to its continued and prolific increase in demand. Today, natural gas is an environmentally preferred fuel used to meet domestic power requirements. Efficient production and protection of established natural gas reserves is of paramount value and importance in light of national energy, security, and economic interests.
Currently, a detrimental phenomenon exists within “dry” gas areas. A dry gas area includes natural gas reservoirs having low water saturation levels and minute amounts or devoid of free water or liquid hydrocarbon production throughout its early life. However, during mature production years, methane rich natural gas reservoirs commence to show signs of fluid loading. In the past, operators have attempted to counteract fluid loading with mechanical adjustments to the well such as, for example, pumping units, plunger lifts, down-sized tubulars, and down-hole separators and soap sticks. All of which require a fluid loaded environment to operate. While sometimes offering temporary relief, these mechanical adjustments have no permanent impact on the ill effects of fluid loading. As a result of an operator's inability to cope with this phenomenon, the individual well is usually prematurely abandoned resulting in a major loss of developed gas reserves.
The Arkoma basin, among others, offers a unique opportunity to review the performance of a typical dry marginal gas well. When individual test well data is sufficient, pressure-cumulative performance will indicate literally thousands of wells subject to excessive fluid build-up. As many as 10,000 wells in the Arkoma basin are threatened by this phenomenon which may result in an average estimated loss in gas reserves in excess of approximately 100 million cubic feet (MMCF) per well if not operationally confronted and corrected. Therefore, a potential loss of one trillion cubic feet of gas reserves may be lost and several billion dollars in lost income to operators and the respective states involved. The domestic impact of this poor performance could translate into significant loss to the nation's energy reserves since the Arkoma Basin may represent only 0.5% or less of total reserves.
The cause of this poor and deteriorating latter stage performance of a reservoir is the result of adverse gas-water phase behavior. Traditionally, the handling and processing of gas and its attendant fluids commences at the immediate wellhead delivery while little or no attention is directed to processing the gas prior to this point in the process. However, a great deal of physical transition occurs from the reservoir extremity, to near well-bore, to entry at down-hole perforations and ultimately through the tubular train to the surface wellhead. Behavioral effects are extremely damaging to production as gas approaches near well-bore. In particular, as gas approaches near well-bore, pressure-temperature reduction is severe causing the deposition of phase-water that is fresh in nature. Though phase-water deposited in this region may initially appear minute (for example, a few gallons per day) to an operator, over a prolonged period of time, the entire well-bore vicinity becomes re-saturated. For example, a reservoir with an initial water-saturation of 17% may re-saturate to a level of 80% in the near well-bore vicinity. The result of this re-saturation severely affects gas-to-water permeability (Kg/Kw) and restricts the rate of natural gas flow, proportionally. When gas enters the well-bore and vertical production tubular train on its way to the surface, a pressure-temperature drop occurs resulting in condensate water deposition. This condition will occur within the vertical flow train when minimum gas flow rates are not met for the existing tubular geometry. Because only a few gallons of water are deposited per day in this region, at this stage, a production problem is unrecognized.
Natural gas production problems are recognized only when fluid loading becomes critical enough to disrupt performance and gas production rate of the reservoir. That is, this critical fluid loading point is reached when the pressure and gas rate have diminished to minimum mist-flow rate conditions of a mature well and the water cannot successfully be lifted. Typically, an operator must mechanically lift the fluid in an attempt to maintain natural gas production.
Other methods of increasing gas well production by dry gas injection have been suggested where dry gas is injected into the formation to force the water into the formation a distance and to dry out the immediate well bore. However, after a period of time, the water will slowly bleed back into the vicinity of the well bore. These previous methods require high volumes of work gas availability which is not available to most low pressure, low volume gas wells.
To this end, a method is needed to reverse the adverse effect of fluid loading by utilizing the relationship of water-gas phase behavior in order to increase overall natural gas production of a gas well whereby condensate water is substantially removed from the flow train. Within this water-phase gas behavior relationship, pressure, temperature, and water-content (expressed as pounds/million cubic feet (#/MMCF)) are factors. Clearly, adjustments or manipulations to pressure and temperature profiles are extremely difficult, if not economically unsound; however, water-content control is feasible. It is to the aforementioned problems to which the present invention is directed.